Barrels Of Oil Research Articles

The Oil Supply Chain in Texas: Pipelines, Tankers, and Trucks

The US EIA states that Texas produced 3,140,000 barrels of oil per day in 2014. Therefore the annual production of crude oil in 2014 was around 1,146,100,000 barrels – see Figure 1. The average cost of ‘West Texas Intermediate’ crude oil was $95 in 2014. So this turns out that $108,879,500,000 worth of crude oil was produced in Texas in 2014. The cost of transportation decides a fraction of final price of a barrel of oil. It accounts for almost 10%-15% of the final price per barrel of oil. If we are able to reduce the costs in the transportation of oil, we will be able to save a significant amount of money that can be utilized somewhere else to make the Texas economy even stronger.

BOOTSTRAP REGRESSION BASED ON THE MAXIMUM ENTROPY IN FORECASTING SOCIO-ECONOMIC INDICATORS

The work is devoted to the actual problem of creating predictive models and evaluating their adequacy based on bootstrap-the method of virtual expansion of statistical sampling. One of the modified bootstrap algorithms based on the entropy maximum is used as an approach for constructing probabilistic statements. The bootstrap method allows you to simulate a large number of random samples within the forecast interval based on the initial sample, represented as a time series of changes in a particular indicator, and evaluate the statistical characteristics of the indicator of interest. The main problem of time series forecasting using the bootstrap method is the need to preserve the dependence of the current indicator value on previous observations, as well as to take into account other factors that affect the process, i.e. the use of regression models. The maximum entropy bootstrap method allows you to generate samples for each indicator that satisfy the ergodicity theorem, while preserving the original form and time dependence of the autocorrelation and partial autocorrelation functions. The maximum entropy bootstrap algorithm is used for cases when the time series is short, non-stationary, with sharp changes in the values of variables and discontinuities. The paper provides an example of using the bootstrap method based on the maximum entropy in relation to the task of creating predictive models to assess their adequacy, which allow us to forecast the indicators of imports and exports of the Russian Federation in billions of us dollars. under the conditions of observing the ruble exchange rate against the us dollar, as well as the indicator of the cost of a barrel of oil on the world market. The results obtained allow us to conclude about the advantages of the considered approach to implementing bootstrap regression for creating predictive models.

Preliminaries Study of Pilot Project Carbon Capture Utilization and Storage in An East Java Oil and Gas Field

A preliminary study for Carbon Capture Utilization and Storage (CCUS) pilot project in an East Java oil and gas field Indonesia has been conducted. CCUS projects have dual purposes: providing a means for increasing production in declined oil fields and reducing greenhouse gas emissions from oil and gas sector by injecting the separated CO2 into the declined oil and gas reservoir. CCUS will be attractive in Indonesia since it could offer additional income for the country from the incremental oil and gas productions and the implementation could use the existing regulations that valid for oil and gas sector. The study of a CCUS pilot project plan has been conducted in order to make sure that the reservoir is suitable for CO2 EOR storage. The CCUS pilot project plan is situated in an oil onshore field in East Java province, Indonesia, which was discovered in 2001. It is situated in the Tuban block, and has nearly 308 million STB of oil in place and more than 100 million barrels of oil in cumulative production. The chosen oil field for has been in production decline for several years and yet the efforts to increase recovery, such as water injection, have been ongoing. Suitability for a CO2-EOR operation is dependent on the petrophysical properties of the reservoir, such as porosity, permeability, and fluid saturation, as well as in-situ reservoir fluid properties such as oil density and viscosity. Reservoir depth is also a key parameter in making a decision as it will impact the miscibility and interaction between CO2 and oil phases. This CO2 EOR pilot project consists of a total of five wells – four production wells at the four corners of a square with an injection well in the middle. The preliminary design for a pilot scale is based on the available CO2 from the field itself, which currently produces 4.4 million SCF (240 tones) of CO2 per day. This pilot-scale test is aimed at examining the performance and viability of a gravity stable CO2 flood. The proposed CO2 injection volumes at the pilot scale are 5 million SCFD respectively, which are estimated to correspond to a production increase of 400 BOPD. For a gravity (gas cap) drive EOR system, the gas (in this case CO2) will be injected into the gas cap above the producing zone. This will help in driving the oil down to the production zones and into the production wells. When injecting into the gas cap, the wellbore integrity in the gas zone and just above the gas zone in the sealing layer must be evaluated. This is to ensure that the CO2 does not escape up the wellbore outside the casing and enter a higher layer. It is essential to include well integrity in the baseline monitoring program to evaluate periodic changes in the well integrity with injection. Monitoring is crucial for the success of a subsurface CO2 injection operation. CO2 injection monitoring is used to verify and compare the injection behaviour with reservoir simulation predictions as well as monitor for potential CO2 leakage through faults or wellbore and avoid any CO2 migration to and accumulation at the surface.

Development of an Integrated Carbon Capture, Utilization, and Storage Hub in the United States

The Integrated Midcontinent Stacked Carbon Storage Hub (IMSCS-HUB) is a first of a kind carbon capture, utilization, and storage (CCUS) project in the midwestern United States. The project is supported under the US Department of Energy’s Carbon Storage Assurance Facility Enterprise (CarbonSAFE) program. The IMSCS-HUB will collect 15 million metric tonnes (MT) per year or more in Iowa and Nebraska and transport it to saline and CO2 enhanced oil recovery (EOR) storage sites in western Nebraska, Kansas, and Texas. Sources include multiple ethanol plants (approximately 1.8 MT/Year), coal fired electric plants (approximately 12.6 MT/Year), and natural gas fired electric plants (approximately 0.6 MT/Year). The passage of an updated tax credit for storage in February 2018 provides a strong economic driver for all of the sources in the hub to develop a hub project. The tax credit provides approximately $50/T for CO2 stored in saline storage units and $35/T for CO2 stored as part of CO2-EOR production. In addition, the inclusion of many bio-energy sources such as ethanol plants allows for early implementation of the project by taking advantage of inexpensive capture ($10/MT to $12/MT) and subsidies from California’s Low Carbon Fuel Standard program. Capture cost estimates for the electric utilities is approximately $33/MT. Transport costs range from $0.6/MT to $5.40/MT. Storage costs range from $3/MT to $4/MT. The hub partners include Battelle, Advanced Resources International, Archer Daniels Midland, Nebraska Public Power District, and others. The region of the project stretching from eastern Iowa to southwestern Nebraska acts as a source corridor, where sources add CO2 to the transport network. The transportation network will consist of a common carrier trunk line designed to connect the largest sources. Smaller sources will be connected through spur lines. The final routing will be selected using the location of existing rights away and environmental factors such as resource locations the critical species habitats. SimCCS and other tools will be used to finalize the routes. The region of the project from southwestern Nebraska to southwest Kansas in a storage corridor where CO2 may be stored in either saline projects or CO2-EOR projects. South of Kansas the CO2 will be transported to Texas for utilization in CO2-EOR. Two saline storage sites and two EOR opportunities have been identified as anchor projects for the storage corridor. The anchor sites are at the northern and southern sides of the storage corridor and will act to validate the storage potential of the entire corridor. In Nebraska saline storage is being planned in Perkins county and CO2-EOR is being studied at Sleepy Hollow Field in Red Willow county. In Kansas, saline storage and CO2- EOR are being planned for Patterson-Heinitz-Hartland (Patterson) Field in Kearney County. Multiple storage formations occur vertically at each site allowing for stacked storage minimizing the surface footprint for monitoring and maximizes the use of storage resources at each site. Data from new tests wells or seismic surveys for each of the sites has been used to create detailed geologic and reservoir models. Modeling for each of the anchor saline sites indicates at least a 50 million tonne storage capacity. The CO2-EOR projects are expected to utilize 2.2 MT and 3.9 MT of CO2 and produce 4.3 and 9.8 million barrels of oil for Sleepy Hollow and Patterson Fields, respectively. The inclusion of CO2-EOR along with saline storage adds an additional economic driver for the project with an estimated revenue of $128/MT and $154/MT of CO2 utilized. The results of the first two phases of the project demonstrate the feasibility of the midcontinent hub concept that couples a diverse set of redundant sources to multiple saline and CO2-EOR projects. The results show that the economics and geology are favorable for early implementation of commercial scale CCUS. The existence of low carbon fuel standard subsidies, storage tax credits, and revenue from produced oil act as economic drivers to support the hub in addition to the climate benefit gained by storing CO2 the hub supports local agriculture and oil production helping to create public support. This presentation will discuss the project development and project economics and how they relate to both stacked saline storage and CO2-EOR in the development of a storage hub. The development of a hub project allows the transport of CO2 from areas such as Iowa that have poor storage potential to areas such as western Nebraska, Kansas, and Texas that have high storage potential. This is critical to the implementation of CCUS in the midcontinent US. The presentation will also discuss the advantage of including redundant sources and sinks to develop a CO2 market that can sustain itself as a commercial enterprise after government funding ends.

North Alaska Super Basin: Petroleum systems of the central Alaskan North Slope, United States

North Alaska Super Basin oil fields have produced more than 18 billion bbl of oil with at least 5 billion bbl remaining in existing fields, and estimated yet-to-find resources exceed 10 billion bbl in three prolific petroleum systems. Since discovery of the two largest United States conventional oil fields at Prudhoe Bay and Kuparuk River in the 1960s, technological advancements including three-dimensional seismic data with amplitude vs. offset analysis, horizontal and extended reach drilling, and identification of source rocks for light oils have enabled new discoveries including Willow and Pikka. Oil in the Prudhoe Bay field is interpreted as a mixture cosourced by lateral migration from Triassic Shublik Formation shale and carbonate, Lower Cretaceous highly radioactive zone (HRZ) shale, and Lower Jurassic Kingak Shale. The bulk properties of Prudhoe Bay main field oils are consistent with the modeled oil composition expelled within the fetch area, and the presence or quality of carrier beds apparently did not affect oil migration efficiency. The Shublik Formation is interpreted as the oil source for Kuparuk River field, the HRZ shale is interpreted as the oil source for Tarn field, and the Kingak Shale is interpreted as the oil source for Alpine field. Point McIntyre field is interpreted as sourced by the same three source rocks as Prudhoe Bay field, and Fiord field is interpreted as cosourced from Shublik and Kingak. West Sak field is interpreted as a mixture of moderately biodegraded oil that spilled from the Prudhoe Bay field and lightly biodegraded condensate that leaked from the underlying Kuparuk River field.

Produced Water Treatment Design Methods in the Gas Plant: Optimization and Controlling

Oil and gas industry produces a huge volume of produced water that contains hydrocarbons, heavy metals, and other pollutants. In the oil and gas industry, produced water, treatment, and management represent a growing challenge. Increasing the oil and gas industry activities, the production of produced water is increased all productions areas all over the world. Its treatment for reuse, management, and disposal represents a significant challenge from an environmental perspective. It is estimated that for every 1 barrel of oil produced, there are 8 to 10 barrels of produced water recovered. In this paper, a comparison of the different techniques for the primary and secondary produced water treatment that are widely applied in industry was investigated to choose the best applicable technology to achieve the required treated produced water specification in the gas project. A technical and economic comparison were conducted. It has been found that de-oiling hydrocyclone followed by induced gas flotation unit is the best choice.

Building a Defensible Digital Network Business

Andrew Bruce’s path to building a digital business offers a map of hazards for those selling digital services to oil companies. When he started Data Gumbo, he was thinking about building a business aimed at solving the data quality issues that were a constant headache when he was working on developing digital control systems at NOV. One option was a fee-for-service business that cleaned up drilling data. While he knew that would make the engineers happy, he wondered if accountants would notice. Clean data ultimately can have a large financial impact by facilitating the digital transformation. But, for those doing financial statements, it is easy to miss because it does not have a direct impact on the bottom line, even though it can facilitate digital changes that do. As he searched for a better idea, he began thinking about building around a blockchain network. At the time, blockchain was only associated with keeping a record of virtual currency ownership. But he could see uses for an immutable record of contracts and transactions in the drilling business, where contract disputes, audits, and wrangling over bills are costly, time-consuming rituals. The plans required only specific bits of operational data, such as the volume of product loaded or the time of delivery, to measure performance based on the contract terms. Building a service that minimizes the customer data needed removed a potential sticking point in negotiations. Years passed as he worked to find users willing to work together to create a blockchain network to see if multiple companies could make this idea work in an oil field. Another thing that kills many startups is time. Investments by the venture arms of Equinor and Saudi Aramco gave Data Gumbo the cash to slowly recruit buyers and sellers to create and test whether the network he envisioned, known as GumboNet, actually could deliver on its promise of faster, argument-free billing that saved money. The most public example was the result of a test by a multicompany consortium in 2019 that showed a paperless system for tracking water or any other oilfield commodity can work accurately and deliver results efficiently. That was the prelude to more testing, until the oil price crash forced the industry to accelerate its search for ways to lower the cost of producing a barrel of oil. The crash sped the transition from testing to field uses and helped expand the company’s customer base. Data Gumbo has added locations in the Middle East and South America. One downside of success: It offers a model for potential competitors. “It is always a concern. It would be naive to say it is not. Anyone can use blockchain tomorrow,” Bruce said. What is harder to do is build a network of users, such as GumboNet. Assembling a group of users who understand the rules and trust the system—like a large group of merchants willing to accept a particular credit card—is a hard thing to replicate. To strengthen those ties, Bruce continues to look for new ways to generate value for users. One idea that he said is on the way this year is a service that uses data associated with logistics contracts, such as water truck traffic data, to generate emissions or water use data to help answer tough questions raised by investors requiring environment, safety, and governance reports.

Study Investigates Using Borehole Gravity To Improve Reservoir Monitoring

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30626, “Brazil Presalt, Santos Basin: Feasibility Study for the Application of Borehole Gravity To Improve Reservoir Monitoring,” by Zhijun Du, Adrian Topham, SPE, and Jeremy C. Lofts, SPE, Silicon Microgravity, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The complete paper uses a feasibility study to present the potential application of a three-axis gravimeter borehole measurement in the Libra presalt reservoir in the Santos Basin offshore Brazil. The authors’ findings suggest that an annual survey with a limited well stock could be effective in monitoring this type of reservoir and that a wireline-deployed three-axis gravity tool is likely to provide significant additional surveillance to constrain a reservoir production strategy through better appreciation of the direction of water movement. Introduction The giant Brazilian presalt reservoirs are in ultradeep water (greater than 2000 m) and buried at a depth surpassing 5000 m. In order to conduct reservoir monitoring and achieve successful reservoir management, borehole-based geophysical technologies are preferred because the measurements can be made closer to the reservoir mass. The development of a borehole gravimeter suit-able for use in deep reservoirs, however, poses significant technical challenges, and breakthroughs have been limited by the sensor form factor (size) and measurement stabilization. By use of microelectromechanical-system (MEMS) vibrating-beam technology, the authors introduce a borehole gravimeter that enables the recording of gravitational acceleration at very high sensitivity. The new resonant MEMS gravitational sensor is designed to sense mass in the subsurface such that time-lapse wireline-based surveys can be conducted to build a picture of fluid movements at relatively large distances from a wellbore, thereby enabling time-lapse or 4D gravity monitoring. The innovation of the three-axis gravimeter also allows the acquisition of directional information about the spatial movement of fluid, even when acquired from only a single borehole. The principles of measuring gravity in the borehole environment are provided in the complete paper. Libra Field. The field is one of the largest presalt oil discoveries in the Santos Basin. It was discovered in May 2010 with recoverable resources of approximately 9 billion bbl of oil. The first appraisal well was completed and tested in February 2015. At the time of writing, nine appraisal wells have been drilled. A high-density 3D seismic program was acquired over the Santos and Campos basins, and advanced seismic processing technology has also been applied. Reservoir Simulation. The geophysics for reservoir characterization and simulation of these carbonate reservoirs is still in its early stages, and little published knowledge about their properties exists. Nonetheless, since their discovery, 2D and 3D seismic technologies have been applied intensively for imaging the region structures and delineating the reservoirs.

What did NAM do to get a social licence to operate? The social impact history of the Schoonebeek oilfield in the Netherlands

From 1943 to 1996, the small rural community of Schoonebeek in the eastern Netherlands hosted the largest onshore oilfield in western Europe. Some 250 million barrels of oil were produced, bringing prosperity to the municipality and local community. With generous compensation paid by NAM (Nederlandse Aardolie Maatschappij, a partnership between Shell and ExxonMobil), local people greatly benefited from oil extraction. However, there were also negative social impacts, including: an influx of outsiders; changes to social structure, social fabric, social cohesion, and community identity; disruption to the peaceful rural setting; and industrialisation of the landscape. Nevertheless, the oil pumping installations (‘jaknikkers’ or nodding donkeys) ultimately became positive symbols of local place identity. Despite the negative social impacts, oil production came to be viewed positively by most local people, and a high level of trust developed between the host community and NAM because of the social performance strategies that were implemented: NAM employed many local people; minimised physical displacement; provided generous compensation for economic displacement; respected the social, cultural and religious wishes of the host community; and quickly addressed any social or environmental issues that developed. These actions meant that NAM gained a strong social licence to operate and grow.

Twelve years of unconventional oil and gas development: production performance and economic analysis

Unconventional formations have been actively developed in the US since 2008. However, it is challenging to quantify the impact of technological advancement and geology on production. In addition, the economics of unconventionals is not well-understood. In this paper, we studied five major unconventional formations in the US: the Bakken, Eagleford, Haynesville, Marcellus, and Wolfcamp formations. We used historical data to quantify the impact of technological and geological variations on production. To accomplish this, we identified four phases of unconventional development over the past 12 years during which drilling and completion technology, initial investment, and commodity prices were similar: Phases 1–4. Using statistical analysis, we compared well performance of each phase. Then, we generated type curves for each phase for economic studies. Initial analysis shows that between January 2008 and December 2019, 60,611 horizontal wells were completed in these formations, producing about 8.185 billion barrels of oil, 90 trillion cubic feet of gas, and generating an estimated $816 billion in gross revenue. For the statistical analysis, the level of uncertainty ( $${P}_{10}/{P}_{90}$$ ratio) reduced from Phase 1 to Phase 4 across all formations, suggesting consistent improvements in well productivity over time while county-level analysis shows spatial disparity in well performance. We infer that technology drives temporal changes while geology drives spatial differences in well performance. From economic analysis, Phase 4 type wells had the best production performance, partly, due to improved drilling and completion efficiency. It was also because operators targeted their best acreage to maximize their asset’s potential.

Forecasting Economic Indicators by Applied Technologies of Data Processing

Today economic forecasts are necessary to identify possible goals of business and society development in general. Available models of information processes of economic system functioning differ by methods of mathematic tools usage. The degree of algorithm complexity with regard to their advantages and drawbacks cannot give an opportunity to choose one method without certain changes. For example, when the trend line is plotted usually only one economic indicator is used, however practice shows that in forecasting it is necessary to take into account several interdependent factors. Standard applied software products are rather expensive and to resolve the set tasks some additional instrumental means, tuning and users’ training are needed. The article proposes a method of plotting the trend line for several economic indicators simultaneously by using tools of widely spread software. The results of using the method for finding the common trend line for the rate of Euro to Russian ruble and the cost of oil barrel (3D) were shown. Apart from that the mathematic instrument for n -dimension case, which later could allow us to assess the possibility of changing several economic indicators at once and analyze their mutual impact.

Qualitative and energy recovery potential analysis: plastic-derived fuel oil versus conventional diesel oil

Due to depleting fossil fuel sources, plastic-derived fuel oil (PDFO) has received much attention over the past decade as an alternative to conventional diesel oil. Although several researchers have reported the properties of PDFO and recommended its usage in diesel engines, no study has thoroughly compared it with conventional diesel oil. This study aims at comparing PDFO produced from pyrolysis of waste plastic (LDPE, HDPE, PS, and PP) with conventional diesel oil based on a number of quality parameters and energy recovery potential. The quality parameters of color and appearance, water content, density, viscosity, volatility, copper strip corrosion, flash point, pour point, and energy content, as well as the cetane index of the fuels, were assessed following ASTM standards. The obtained results indicated no significant difference between the water contents and densities of the fuel oils. Pensky–Martens Closed Cup (PMCC) flash point for PDFO was significantly lower than that of conventional diesel oil. Although the pour points and viscosities of PDFO were significantly different from conventional diesel oil, the values were within the recommended range. All the PDFO types had higher volatilities than conventional diesel oil in the lighter section of the distillation curve, whereas no significant difference was detected in the heavier section. On the ASTM corrosion chart, conventional diesel oil belongs to class 1a, whereas all the PDFO types belong to class 2a. Energy recovery calculations revealed that PDFO has the potential to produce energy equivalent to 203,000 barrels of oil. It can be concluded that although PDFO has undesirable high volatility in the lighter section of the distillation curve and relatively low flash point, it compares relatively well with conventional diesel oil and thus is a potential substitute.

Chemical enhanced oil recovery and the dilemma of more and cleaner energy

A method based on the concept of exergy-return on exergy-investment is developed to determine the energy efficiency and CO2 intensity of polymer and surfactant enhanced oil recovery techniques. Exergy is the useful work obtained from a system at a given thermodynamics state. The main exergy investment in oil recovery by water injection is related to the circulation of water required to produce oil. At water cuts (water fraction in the total liquid produced) greater than 90%, more than 70% of the total invested energy is spent on injection and lift pumps, resulting in large CO2 intensity for the produced oil. It is shown that injection of polymer with or without surfactant can considerably reduce CO2 intensity of the mature waterflood projects by decreasing the volume of produced water and the exergy investment associated with its circulation. In the field examples considered in this paper, a barrel of oil produced by injection of polymer has 2–5 times less CO2 intensity compared to the baseline waterflood oil. Due to large manufacturing exergy of the synthetic polymers and surfactants, in some cases, the unit exergy investment for production of oil could be larger than that of the waterflooding. It is asserted that polymer injection into reservoirs with large water cut can be a solution for two major challenges of the energy transition period: (1) meet the global energy demand via an increase in oil recovery and (2) reduce the CO2 intensity of oil production (more and cleaner energy).

Feasibility analysis of mini hydropower and thermal power plants at Hindiya barrage in Iraq

Mini hydropower plants can be considered as good instruments for power generation at a low cost with high efficiency. This study is undertaken to help address the electricity shortage that Iraq has faced for many decades. This study covers the design and analysis of two alternatives, which are hydropower and thermal power plants, through a mathematical financial feasibility approach. The study area is Hindiya barrage on the Euphrates River. A complete design of the powerhouse plant is presented. In the thermal power plant, two proposals were tested, one at a cost of 60 US$ per barrel of oil and the other at 30 US$. Most of the financial parameters are considered. The hydropower plant generation is more feasible than the thermal power generation. This result provides the impression of a low payback period in the power production from the established barrages on the Euphrates and Tigris rivers.

Prediction of oil flow rate through orifice flow meters: Optimized machine-learning techniques

Flow measurement is an essential requirement for monitoring and controlling oil movements through pipelines and facilities. However, delivering reliably accurate measurements through certain meters requires cumbersome calculations that can be simplified by using supervised machine learning techniques exploiting optimizers. In this study, a dataset of 6292 data records with seven input variables relating to oil flow through 40 pipelines plus processing facilities in southwestern Iran is evaluated with hybrid machine-learning-optimizer models to predict a wide range of oil flow rates (Qo) through orifice plate meters. Distance-weighted K-nearest-neighbor (DWKNN) and multi-layer perceptron (MLP) algorithms are coupled with artificial-bee colony (ABC) and firefly (FF) swarm-type optimizers. The two-stage ABC-DWKNN Plus MLP-FF model achieved the highest prediction accuracy (root mean square errors = 8.70 stock-tank barrels of oil per day) for oil flow rate through the orifice plates, thereby removing dependence on unreliable empirical formulas in such flow calculations.

An Emerging CO2 Storage Option: CO2 Storage and By-Product Oil Recovery from Shale Oil Formations

Recent studies, sponsored by the United States Energy Association (USEA) and prepared by Advanced Resources International, have identified an emerging CO2 storage option – injecting and storing CO2 in shale oil formations. Because this CO2 storage option also provides by-product oil recovery, it offers a source of revenues and thus a potential “business case” for pursuing CO2 capture and storage. Shale oil (also called tight oil) has become the dominant source of U.S. oil production, increasing from less than 1 million barrels per day (MMB/D) a decade ago to about 8 MMB/D at the end of 2019. In addition, large shale oil basins and resources exist in many parts of the world, including Argentina, Australia, Canada, China, North and South Africa, and other settings, as evaluated by our company for the U.S. Energy Information Administration. (World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, April 2011) Because of ultra-low permeability, oil recovery efficiency from shale oil formations using primary (pressure depletion) practices is low, on the order of 5 to 10% of the original oil in-place (OOIP). This leaves behind a large resource target for application of more advanced shale oil recovery technologies. Use of advanced recovery practices involving the injection of CO2 into shale oil formations (Shale EOR) provides one such technology and thus an additional pathway for economically viable storage of CO2. While a series of CO2 injection pilots are underway in U.S. shale oil basins, industry has held the results of these pilots “close to the vest.” To overcome this lack of information, the USEA sponsored a series of studies, involving the use of geologic characterization and reservoir engineering, to examine the potential of Shale EOR in four major U.S. shale oil basins - the Bakken Shale, the Eagle Ford Shale, and the Wolfcamp Shale in the Midland and Delaware Basins of the Permian Basin. This work showed that cyclic injection of CO2 can lead to additional recovery of oil from these shale oil formations while trapping and storing significant volumes of CO2. The study involved building a geologic model for a representative portion of each shale oil formation, history matching reservoir properties with well completion practices against actual well performance, and using a compositional reservoir simulator (GEM) to calculate oil recovery and CO2 storage from Shale EOR. Shale reservoir characterization and modeling for a “type area” of the Wolfcamp Shale in the Midland Basin illustrates the methodology and results of the Shale EOR study. With 12 cycles of CO2 injection, soak and production (over 8.5 years), Shale EOR stored 102,000 metric tons of CO2 in a representative 180-acre well pattern of the Wolfcamp Shale, while producing 223,000 barrels of shale oil. The 223,000 barrels of incremental oil, in addition to 355,000 barrels from primary oil recovery, provided an uplift of 63% in oil recovery. Using an additional CO2 injection cycle followed by well shut-in, Shale EOR stored 155,000 metric tons of CO2 in this 180-acre Midland Basin’s Wolfcamp Shale “type pattern”, equal to 0.7 metric tons of CO2 stored for every barrel of incremental shale oil produced. Similar evaluations of cyclic CO2 injection in other shale basins also showed that with Shale EOR more CO2 could be stored than the CO2 content in the oil produced. The Bakken Shale had a CO2 stored to oil produced ratio of 0.62 metric tons per barrel, the Eagle Ford Shale had a ratio of 0.39, and the Wolfcamp Shale of the Delaware Basin had a ratio of 0.69. As such, given that the combusted portion of a barrel of oil creates 0.38 metric tons of CO2, Shale EOR enables more CO2 to be stored than the CO2 content in a barrel of oil when combusted. (Approximately 12% of an oil barrel is used for petrochemicals and other non-combustion sources.) The study noted that special geologic conditions and development practices are important for optimum application of the cyclic CO2 injection and storage process. Future pathways being evaluated for this emerging CO2 storage option and a potential new “business case” for CCUS include: (1) examining continuous, rather than cyclic, injection of CO2 and (2) using conformance and other CO2 storage enhancing technologies. These technologies would appreciably increase the volumes of CO2 able to be stored as well as improve the oil recovery efficiency of Shale EOR.

E&P Notes (January 2021)

E&P Notes (January 2021)

GARCH and Its Variants’ Model: An Application of Crude Oil Distributions in Nigeria

This study investigates the need for variants of GARCH model when the former fails to fully embrace clumping volatility of either a positive or negative shock via asymmetrical effect, long-memory, high-frequency, and leverage effect. The volatility effect of distributions of crude oil (prices, barrels produced and exported) in Nigeria, for the period of fifteen (15) (1: 2006 to 8:2020) years obtained from Nigeria National Petroleum Corporation (NNPC) bulletin were examined via GARCH and it variants. Exploratory Data Analysis (EDA) and time plot analyzes were carried-out on the one hundred and seventy-six (176) data points. It was deduced that GARCH (2,1) optimally generalized the prices of crude oil among its variants of gjrGARCH (2,1), apARCH (2,1), iGARCH (2,1), and csGARCH (2,1), and that positive and negative shocks did not have the same impact on the volatility of prices of crude oil. In a similar vein, iGARCH (1,1) optimized barrels of crude oil produced and exported among eGARCH (1,1), GARCCH (1,1), gjrGARCH (1,1), apARCH (1,1), iGARCH (1,1), and csGARCH (1,1) for the years of studied. However, it was inferred that positive shock as real meaningful impact on the clumping volatility on barrels of crude oil produced and exported while negative shock as no meaningful impact on the volatility on barrels of crude oil produced and exported.

Manuela DraegerEleven Sooty Dreams by J. T. Mahany

precious resources that lie in the ground could be the salvation of the Dené. But tying an entire culture’s future to the price of a barrel of oil is too risky for others. As one Dené elder tells Sacco, “The government pulled people out of the bush to put their children in schools, and they graduated from their independence [on] the land into a money-based economy with no jobs.” Sacco provides no answers in what is his finest, most layered work to date. But one thing stands evident, as a young activist points out: the “defined system[s] of colonization and governance are not there for us to succeed as land users, they’re there for capitalism to succeed.” J. R. Patterson Gladstone, Manitoba Manuela Draeger Eleven Sooty Dreams Trans. J. T. Mahany. New York. Open Letter. 2021. 140 pages. ELEVEN SOOTY DREAMS is the latest book out in English by one of Antoine Volodine’s postexotic heteronyms, Manuela Draeger (see WLT, Autumn 2020, 22). Draeger, whose name is on several books for adolescents and whose first book in English, In the Time of the Blue Ball, was published in 2011, now brings us a story about a group of young people trapped in a burning building during a protest and reliving their memories just before the flames and death consume them. Like Volodine’s other imaginary writers of the postexotic (by which Volodine means “beyond genre categories”), Draeger explores the power of dreams, the potential landscape of the afterlife, and a surreal world populated by characters who can transform, live forever, and alter their states of consciousness. Each of Draeger’s “sooty dreams” depicts a different person’s (or elephant’s!) memories or experiences moving through the Bardo (or afterlife). Granny Holgode, who seems to grow younger as time passes, acts as the unofficial leader of a group of ragged adults and children clinging to the Bolshevik beliefs of the defunct Second Soviet Union. Like Gramma Udgul in Volodine’s Radiant Terminus, Granny Holgode somehow defies time and lectures her listeners on the glory of the revolution with a kind of mesmerizing force. But while Gramma Udgul lives under the cloud of the Second Soviet Union’s recent collapse, Granny Holgode presides over the ruins of long ago. For Marta Ashkarot, death means turning into a talking elephant who undergoes reincarnation multiple times. Children like Imayo Özbeg and Rita Mirvrakis form a powerful bond of love and mutual support, even in the face of loss, death, destruction, and genocide. At one point, as they wander the streets looking for a long-lost relative, Rita cautions, “It’s better not to believe in the present.” In other “dreams,” a corpse speaks to his sister from the wire fence upon which he was impaled, and an insane soldier takes over teaching school each time the regular teacher is shot for not toeing the party line. Characters wander around the ruins of their city wearing boards around their necks that exhort strangers to kill or dissect them because they’re sub/inhuman. After death, the voices Draeger has summoned up are transformed into what Granny Holgode calls “strange cormorants” (as she’d told the children, “perishing in fire during combat opens the door to an immediate metamorphosis” into one of these creatures). From the “sooty heap” created out of the bodies consumed by fire emerges one voice—Imago Özbeg’s—to point the way forward to the next incarnation. Translator J. T. Mahany channels the soot, despair, revolutionary zeal, and incorruptible love in his powerful translation, allowing anglophone readers to delve deeper into the unique postexotic world of Volodine and Friends. Rachel S. Cordasco Madison, Wisconsin Giuseppe Ungaretti Allegria Trans. Geoffrey Brock. New York. Archipelago Books. 2020. 204 pages. THE ITALIAN WORD allegria does not have a true equivalent in English, which makes Allegria a sensible choice for the title of this translation. Moreover, Allegria subtly fuses Allegria di naufragi (1919) and L’Allegria (1931), which are the titles of two early manifestations of the book that originated in Il porto sepolto in 1916 Books in Review 86 WLT WINTER 2021 ...

CO2-EOR+ in Australia: achieving low-emissions oil and unlocking residual oil resources

The petroleum industry, through the production and consumption of oil and gas, contributes to global greenhouse gas emissions. However, the industry’s leadership and experience in underground injection and storage of CO2, especially through CO2 enhanced oil recovery (CO2-EOR), which has been proposed as a possible solution to reducing atmospheric CO2 levels, has not been well acknowledged. Unlike traditional CO2-EOR, which tends to be a net carbon emitter due to the use of predominantly natural CO2, rather than anthropogenic, CO2-EOR+ focuses on storing a larger volume of CO2. Thus CO2-EOR+ not only provides a potential solution to dispose of anthropogenic emissions but at the same time reduces reliance on imported oil through increased domestic production. Increased industry interest and energy policy strategies directed at reducing and/or removing emissions from industry processes reflect the growing social and economic impetus to improve operation practices and the petroleum industry’s reputation. Residual oil zones (ROZs) below identified oil–water contacts provide an excellent target for the application of CO2-EOR+. They offer a producible residual oil resource accessible through CO2-EOR, as well as a large pore volume for CO2 storage, with efforts focused on converting ROZs into resources and reserves. Existing fields in the Surat and Cooper-Eromanga Basins are already well placed to utilise anthropogenic CO2 sources to achieve conventional CO2-EOR metrics. The ROZs in these basins will hopefully allow potential EOR projects to increase the CO2 volumes stored, per incremental barrel of oil, well past traditional levels (0.2–0.3 tCO2/bbl), and in doing so, potentially achieve net negative-emission oil.